Drilling wells for oil and gas production conventionally employs longitudinally extending sections, or so-called “strings,” of drill pipe to which, at one end, is secured to a drill bit of a larger diameter. The drill bit conventionally forms a bore hole through the subterranean earth formation to a selected depth. Generally, after a selected portion of the bore hole has been drilled, the drill bit is removed from the bore hole so that a string of tubular members of lesser diameter than the bore hole, known as casing, can be placed in the bore hole and secured therein with cement. Therefore, drilling and casing according to the conventional process typically requires sequentially drilling the bore hole using drill string with the drill bit attached thereto, removing the drill string and drill bit from the bore hole, and disposing and cementing a casing into the bore hole.
Rotary drill bits are commonly used for drilling such bore holes or wells. One type of rotary drill bit is the fixed-cutter bit (often referred to as a “drag” bit), which typically includes a plurality of cutting elements secured to a face region of a bit body. Referring to FIG. 1, a conventional fixed-cutter rotary drill bit 100 includes a bit body 110 having a face 120 defining a distal or leading end and comprising generally radially extending blades 130, forming fluid courses 140 therebetween extending to junk slots 150 between circumferentially adjacent blades 130. Bit body 110 may comprise a composite matrix formed of hard particles such as a tungsten carbide infiltrated with a binder, conventionally of a copper alloy, a steel body, or a sintered matrix of hard particles such as a metal carbide, all as known in the art.
Some or all of blades 130 may include a gage pad 160 which is configured to define the outermost radius of the drill bit 100 and, thus, the radius of the wall surface of a bore hole drilled thereby. Gage pads 160 comprise longitudinally upward (as the drill bit 100 is oriented during use) extensions of blades 130. The gage pads 160 may have wear-resistant inserts or coatings, such as hardfacing material, on radially outer surfaces 162 thereof as known in the art to inhibit excessive wear thereto, and may also have cutting elements on rotationally leading surfaces 164 thereof to maintain the intended borehole diameter drilled by the drill bit 100.
A plurality of cutting elements 180 are conventionally positioned on each of the blades 130. Generally, the cutting elements 180 have either a disk shape or, in some instances, a more elongated, substantially cylindrical shape. The cutting elements 180 commonly comprise a “table” of superabrasive material, such as mutually bound particles of polycrystalline diamond, formed on a supporting substrate of a hard material, conventionally cemented tungsten carbide. Such cutting elements are often referred to as “polycrystalline diamond compact” (PDC) cutting elements or cutters. The plurality of PDC cutting elements 180 may be provided within cutting element pockets 190 formed in rotationally leading surfaces of each of the blades 130. Conventionally, a bonding material, such as an adhesive or, more typically, a braze alloy, may be used to secure the cutting elements 180 to the bit body 110. Of course, other drill bits configured as drag bits may employ, for example, non-diamond superabrasive cutting structures (e.g., cubic boron nitride), natural diamonds, thermally stable polycrystalline diamond elements, or “TSPs” (thermally stable products), diamond grit-impregnated matrix cutting structures, and combinations of the foregoing, including PDC cutting elements. As known to those of ordinary skill in the art, the drill bit configuration and cutting structures employed are selected in light of the formation or formations intended to be drilled.
The bit body 110 of a rotary drill bit 100 typically is secured to a hardened steel shank 200 having an American Petroleum Institute (API) thread connection for attaching the drill bit 100 to a drill string (not shown). A trailing surface 210 is located between a radially outer surface 162 of each gage pad 160 and a shoulder 220. Transition edges 230 lie at the junctions between the radially outer surfaces 162 of gage pads 160 and their associated longitudinally trailing surfaces 210. Trailing surfaces 210 may each comprise a flat bevel or chamfer, or may be somewhat arcuate. Typically, the trailing surface lies at about a 45° angle to the longitudinal axis of the bit.
During drilling operations, the drill bit 100 is positioned at the bottom of a well bore hole and rotated. Drilling fluid is pumped through passages on the interior of the bit body 110, and out through nozzles (not shown). As the drill bit 100 is rotated, the PDC cutting elements 180 scrape across and shear away the underlying earth formation material. The formation cuttings mix with the drilling fluid and pass through the junk slots 130, up through an annular space between the wall of the bore hole and the outer surface of the drill string to the surface.
When drilling in formation with unconsolidated, highly abrasive sand formations, the radially outer surfaces 162 of the gage pads 160 of the drill bits are subjected to wear caused by the abrasive cuttings being drilled, the high sand content in the mud, and the sand particles along the bore hole wall. Improvements in the wear-resistant inserts and/or coatings have helped to limit the accelerated wear from occurring on the radially outer surfaces 162 of the gage pads 160 in the normal (i.e., downward) drilling mode. However, drilling in hard rock, abrasive formations also results in accelerated wear on the trailing surfaces 210 of the gage pads 160. Further, when a drill bit 100 is rotated in the bore hole as it is withdrawn therefrom, such as when back reaming or “up-drilling” is performed, substantial wear to the trailing surfaces 210 located near the shank 200 end of the drill bit 100 may occur. Wear also occurs when back-drilling to enhance bore hole quality or to remove or remediate “dog legging” in the well bore. This type of wear causes rounding over the gage pads 160 and such wear will eventually compromise the ability of the gage pads 160 to maintain the intended gage of the bit, requiring the bit to be scrapped or, at the least, prematurely repaired.
While PDC cutting elements usable for up-drilling have been placed at the trailing ends of gage pads, such as at the junction of the radially outer surface with the longitudinally trailing surface of the gage pad, such an arrangement is not effective in preventing excess wear and PDC cutting elements alone are not particularly robust for up-drilling due to the discontinuous nature of their engagement with the wall of a previously drilled bore hole. Furthermore, PDC cutting elements are relatively expensive, several PDC cutting elements must be used to afford complete protection to the trailing surface, and PDC cutting elements must be brazed or otherwise secured to the bit body of a bit after manufacture. Thermal limitations of PDC cutting elements preclude them being furnaced into the body of a matrix-type bit during infiltration. Natural diamonds have also been placed in the same area, but the sizes and shapes of natural diamonds require the use of an excessive number of stones.
In addition, when drill bits are used in so-called “steerable” bottom hole assemblies to drill in non-linear paths such as are employed in directional and horizontal bore holes, the trailing surfaces of the gage pads are subjected to increased abrasive wear as the bit is tilted in the bore hole by the steering assembly when drilling a non-linear path.
While rotary drag bits, including full-diameter bits, core bits, bi-center bits and eccentric bits experience the above-described problems, these problems are not so limited. Roller cone bits, so-called “hybrid” bits including both fixed cutting elements and rotating cones or other structures, and other drilling tools such as, by way of non-limiting example, fixed-blade and expandable reamers, all experience similar problems on trailing surfaces of their bodies where necking down to a shank or other smaller-diameter component is used for connection to another component of a bottom hole assembly, or to the drill string itself.